Thermal gradients are commonly used in the oil industry to determine the thermal state of the subsurface. Examples of correlations between variations in thermal gradients and oil and gas horizons in fields within the United States can be found in the literature as far back as the 1920's. More recent examples of such correlations are presented in Meyer, H. J. and McGee, H. W., "Oil and Gas Fields Accompanied by Geothermal Anomolies in Rocky Mountain Region," Am. Assoc. Petr. Geol. Bull. 69, No. 6, 1986, pp. 933-45. An excellent review of this methodology can be found in Roberts, W. H. III, "Some Uses of Temperature Data in Petroleum Exploration in Unconventional Methods in Exploration for Petroleum and Natural Gas," II, ed. B. M. Gottlieb, Inst. Study of Earth and Man, SMU Press, Dallas 1981.
Though the occurrences of oil and gas production zones are sometimes found associated with thermal gradient changes, the correlation has not proved to be consistent. The drilling history of the well severely disturbs the ambient thermal gradients surrounding the well, and equilibrium corrections that must be made to raw temperature measurements are very complicated. Multiple temperature logs, run at several different times in a well, greatly improve the data quality, but such multiple logs are rarely available.
Several techniques have been proposed to measure the thermal conductivity variations, instead of thermal gradients, of the earth formations and fluids in and around a wellbore. In Smith U.S. Pat. No. 3,864,969 for "Station Measurements of Earth Formation Thermal Conductivity" (1975), it is shown that oil and gas bearing horizons have 50-100% lower thermal conductivities than similar lithogies that are water-bearing (FIG. 1). In Smith U.S. Pat. No. 3,892,128 for "Methods of Thermal Well Logging" (1975), there is described a technique for directly logging thermal conductivity in a well in order to determine the locations of oil and gas bearing formations. A special logging tool with a heat source is dragged up the borehole, and the rate of diffusion of heat from the tool into the rock is measured. Similarly, Young U.S. Pat. No. 4,575,260 for "Thermal Conductivity Probe for Fluid Identification" (1986) describes a heater-probe for a logging tool that measures the thermal conductivity of the wellbore fluid, rather than that of the rock. If hydrocarbons are present in the well, the thermal conductivity probe will detect unusually low thermal conductivities.
Neither the measurement of thermal gradient nor thermal conductivity in wells has proved to be a consistent locator of hydrocarbons. The measurement of thermal gradients and thermal conductivities separately in a well gives inconsistent results for the detection of thermal anomalies associated with oil and gas-bearing horizons for a fundamental scientific reason: each alone does not measure the proper physical parameter. The flow of heat from the earth is not measured by either the thermal conductivity or the thermal gradient, but by the product of these two physical properties. Heat flow equals thermal gradient times thermal conductivity at any given depth in a wellbore. If both accurate thermal gradients and thermal conductivities can be ascertained throughout a wellbore, the heat flow at every depth in a well can be calculated.
Determination of heat flow allows the application of fundamental physical laws to the interpretation of hydrocarbon migration and fluid flow in the subsurface. For example, heat flow must be constant with depth if a wellbore is in thermal equilibrium. Fluid convection, geopressuring, and oil and gas migration can all produce heat flow that is not constant with depth in a wellbore. Thus, the thermal gradient at any point in a well may be found to be high because of either low thermal conductivity (e.g., due solely to a lithology change), or because hot, low thermal conductivity fluids have recently migrated into traps penetrated by the wellbore. From the wellbore heat flow, however, it is possible to determine not only the likely locations and possible compositions of hydrocarbons in the vicinity of the well, but also whether fluid flow is active in the region surrounding the wellbore.